1. Field of the Invention
The present invention relates to hydrocracking systems and method for efficient reduction of sulfur and nitrogen content of hydrocarbons.
2. Description of Related Art
Hydrocracking processes are used commercially in petroleum refineries typically to process a variety of feedstocks. In general, hydrocracking processes split the larger molecules of the feedstock into smaller, i.e., lighter, molecules having higher average volatility and economic value. Additionally, hydrocracking processes typically improve the quality of the hydrocarbon feedstock by increasing the hydrogen to carbon ratio and by removing organosulfur and organonitrogen compounds. The significant economic benefit derived from hydrocracking processes has resulted in substantial development of process improvements and more active catalysts.
Mild hydrocracking or single-stage once-through hydrocracking occurs at operating conditions that are more severe than those required in hydrotreating processes, and less severe than those required for conventional full pressure hydrocracking processes. Mild or single-stage hydrocracking operations are typically more cost effective, but conventionally produce a reduced yield of mid-distillate products, and of a relatively lower quality, as compared to conventional full pressure or multiple stage hydrocracking processes. Single or multiple catalysts systems can be used depending upon the feedstock processed and product specifications. Single-stage hydrocracking is the simplest of the various configurations, and is typically designed to maximize mid-distillate yield over a single or dual catalyst systems. Dual catalyst systems can be deployed as a stacked-bed configuration or in multiple reactors.
In a series-flow configuration the entire hydrocracked product stream from the first reaction zone, including light gases (e.g., C1 to C4, H2S, NH3) and all remaining hydrocarbons, is sent to the second reaction zone. In two-stage configurations the feedstock is refined by passing it over a hydrotreating catalyst bed in the first reaction zone. The effluents from the first reaction zone are passed to a fractionating zone to separate the light gases, naphtha and diesel products boiling in the temperature range of 36° C. to 370° C. The hydrocarbons boiling above 370° C. are then passed to the second reaction zone for additional cracking. The configurations are decided based on the processing objectives and the types of feedstock. As feedstock becomes heavier for particular processing objectives, the configurations become more complicated.
Heaviness of the hydrocarbon feedstock implies higher feedstock distillation end point (lower American Petroleum Institute (API) gravity) and higher levels of coke precursors. As the boiling point range of the hydrocarbon feedstock increases, the nitrogen and sulfur heteroatom content also increases. Consequently, the catalyst system encounters high levels of ammonia and hydrogen sulfide while processing such a feedstock. The basic ammonia can neutralize the acidity on the catalyst and thus reduces the overall catalyst activity. Hence, to achieve a target conversion rate, the amount of catalyst required is higher for relatively heavier hydrocarbon feedstocks. Furthermore, the presence of hydrogen sulfide has a negative effect on the overall quantity and quality of the distillate intermediate and final products. Thus, when processing relatively heavy hydrocarbon feedstocks, conventional hydrocracking configurations require higher catalyst volumes, higher pressure and/or multiple stages.
A traditional two-stage hydrocracking system 1000 flow scheme is shown in FIG. 2. Hydrotreating reaction zone 100 includes a reactor 144 containing an effective quantity of a suitable hydrotreating catalyst. Reactor 144 includes an inlet for receiving a combined stream 130 including a feedstock stream 120 and a hydrogen stream 124 and an inlet for receiving a quenching hydrogen stream 146. A hydrotreated effluent stream 140 is discharged from an outlet of reactor 144. In certain embodiments a hydrogen gas inlet stream 124 can be separate from the feed inlet stream 120 as opposed to combining with the feed prior to entering reactor 144 as stream 130 (in addition to the inlet for introducing quenching gas). In the traditional flow scheme that is conventionally used for processing high nitrogen and high sulfur feeds, the hydrotreating zone effluent stream 140 is combined with a hydrogen stream 180 and directly routed as stream 330 to a first hydrocracking zone 300 which includes a hydrocracking reactor 320 that may have single or multiple catalyst beds and receive quench hydrogen stream in between the beds as shown by stream 326.
The first hydrocracking zone 300 is consequently in a sour environment (high ammonia and hydrogen sulfide). Thus, to limit the amount of catalyst required, the degree of conversion in the first hydrocracking zone 300 is limited. The first hydrocracking zone effluent stream 340 passes to separation zone 500 including two separators 510 and 520. The liquid effluent streams 518 and 560 then enters the flash zone 600 (including separators 630 and 640) to produce streams 638, 644, 648 and 650 as shown in the FIG. 2. The hydrocarbon liquid side stream 648 is combined with the bottom liquid stream 638 to form feed stream 690 which enters the fractionation zone 700. The fractionation zone 700 produces the variety of products which includes an overhead stream 710, a first side-stream 720, a second side-stream 730, and a bottom stream 735. Typically, stream 710 comprises naphtha, the first side-stream 720 comprises kerosene and the second side-stream 730 comprises diesel. At least a portion of the bottom stream 735 flows as stream 740 to the second hydrocracking zone 800 and a portion of stream 750 is purged out of the system.
The stream 740 is mixed with recycle hydrogen stream 745 and enters the second hydrocracking zone 800. The second hydrocracking zone 800 includes a hydrocracking reactor 820 which may have single or multiple catalyst beds and receive quench hydrogen stream in between the beds as shown by stream 826. The effluent from the second hydrocracking zone 840 then joins the effluent stream 340 from the first hydrocracking zone 300 and passes to separation zone 500.
A cold high-pressure drum 520 provides an overhead stream 514, which is rich in hydrogen and hydrogen sulfide and is then routed to an amine scrubbing system to remove the hydrogen sulfide. The sweet gas stream 570 which is rich in hydrogen can be recycled back after compression through recycle hydrogen compressor 580 to produce stream 585 that is recycled back to the hydrogen manifold “Header A”. The high purity make-up hydrogen stream 204 from manifold “Header B” is either from a hydrogen plant or from a pressure swing adsorption unit or a reforming unit.
Notwithstanding the state of the art, it would be desirable to provide more efficient hydrocracking processes and systems.